Supplemental Documentation for Scenario Suite
EPA's Power Sector Modeling Platform v6 using IPM
May 2018
1. Introduction
This document describes a suite of scenario runs conducted with EPA's Power Sector Modeling Platform
v6 using IPM (EPA Platform v6). It is supplemental to the full-fledged documentation of EPA Platform v6,
which explains the model parameters, assumptions, and data inputs used in the initial run. This
supplemental document details the input assumptions, data or parameters changed, and tested in each
scenario run incremental to the initial run. Table 1 lists the scenario runs documented in the following
sections of this document.
Table 1 Suite of Scenario Runs Incremental to the Initial Run using EPA Platform v6
IPM Run Name
IPM Run Description
High Demand
Adopted from AEO 2018 high electricity demand case
Low Demand
Adopted from AEO 2018 low electricity demand case
High RE Technology Cost
Using NREL ATB 2017 high RE technology cost case
Low RE Technology Cost
Using NREL ATB 2017 low RE technology cost case
Higher Natural Gas Cost
Reflecting lower resource recovery and higher LNG exports
Tax Law Update
Reflecting The Tax Cuts and Jobs Act of 2017
For any information pertaining to any other parameters, input data, and modeling assumptions (that is not
contained in this document), please consult the EPA Platform v6 full-fledged documentation available at
https://www.epa.qov/airmarkets/documentation-epas-power-sector-modelinq-platform-v6
2. High Demand
EPA Platform v6 high demand scenario run has adopted the growth in demand underlying the AEO 2018
high economic growth case. The electricity demand is calculated as the summation of AEO 2017 no CPP
case demand and the difference in demands between the AEO 2018 High Economic Growth with no CPP
and AEO 2018 no CPP cases. The scenario run implies 2.3% higher demand by 2030 and 8.7% higher
demand by 2050 incremental to the initial run.
For the high demand scenario, Table 2 and Table 3 present the net energy for load on a national and
regional basis respectively. Table 4 illustrates the national sum of each region's seasonal peak demand
and Table 43 presents each region's seasonal peak demand. In the EPA Platform v6 full-fledged
documentation, Table 2 and Table 3 correspond to Table 3-2 and Table 3-3 respectively and Table 4 and
Table 43 correspond to Table 3-4 and Table 3-18 respectively.
1
-------
Table 2 Electric Load Assumptions for the High Demand Scenario
Year
Net Energy for Load (Billions of kWh)
2021
4,107
2023
4,201
2025
4,288
2030
4,463
2035
4,643
2040
4,890
2045
5,138
2050
5,400
Table 3 Regional Electric Load Assumptions for the High Demand Scenario
IPM Region
Net Energy for Load (Billions of kWh)
2021
2023
2025
2030
2035
2040
2045
2050
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
349
361
372
396
418
447
473
498
28
29
30
31
33
35
38
40
233
238
245
260
274
291
307
326
31
32
33
35
37
40
43
45
37
38
39
42
44
47
50
53
22
23
23
25
26
28
30
32
22
22
23
24
25
26
28
29
48
49
50
52
54
56
59
62
97
100
102
105
109
114
120
127
46
48
49
52
55
59
63
66
101
103
104
108
111
117
123
129
8
9
9
9
10
10
11
11
30
31
31
33
34
36
38
40
90
92
94
98
103
108
115
121
41
42
42
44
46
48
50
53
32
34
35
37
39
42
44
47
55
56
57
59
61
65
69
73
30
30
31
31
31
32
33
33
11
11
11
11
11
11
11
12
79
79
80
80
82
83
85
86
15
15
15
15
15
16
16
17
9
10
10
10
10
10
10
10
23
23
23
23
24
24
25
25
6
6
6
6
6
6
7
7
11
11
11
11
11
12
12
12
ERC_FRNT
ERC_GWAY
ERC_PHDL
ERC_REST
ERC_WEST
FRCC
MIS_AMSO
MIS_AR
MIS_D_MS
MIS_IA
MIS IL
MIS_INKY
MIS_LA
MIS_LMI
MIS_MAPP
MIS_MIDA
MIS_MNWI
MIS_MO
MIS_WOTA
MIS_WUMS
NENG_CT
NENG_ME
NENGREST
NY_Z_A
NY_Z_B
NY_Z_C&E
NY_Z_D
NY Z F
-------
IPM Region
Net Energy for Load (Billions of kWh)
2021
2023
2025
2030
2035
2040
2045
2050
NY_Z_G-I
18
19
19
19
18
19
19
19
NY_Z_J
51
51
50
50
49
49
49
50
NY_Z_K
22
22
22
22
22
22
22
22
PJM_AP
48
49
50
51
53
56
59
62
PJM_ATSI
70
72
73
76
78
82
86
91
PJM_COMD
102
105
107
110
114
120
126
133
PJM_Dom
98
101
104
110
115
123
130
138
PJM_EMAC
139
141
143
146
149
155
160
167
PJM_PENE
17
17
17
18
18
19
20
20
PJM_SMAC
64
65
65
67
68
71
73
76
PJM_West
213
218
222
230
238
250
263
278
PJM_WMAC
56
56
57
58
59
62
64
66
S_C_KY
33
34
35
36
38
40
42
44
S_C_TVA
179
185
190
199
207
218
230
244
S_D_AECI
18
19
19
20
20
21
22
24
S_SOU
251
260
267
281
294
312
329
348
S_VACA
226
233
240
253
266
283
300
319
SPP_KIAM
0
0
0
0
0
0
0
0
SPP_N
71
73
75
78
81
85
90
95
SPP_NEBR
34
35
35
37
38
41
43
45
SPP_SPS
30
31
32
34
36
38
40
43
SPP_WAUE
23
24
24
25
26
28
29
31
SPP_WEST
132
136
141
149
157
168
178
188
WEC_BANC
14
14
14
14
15
15
16
16
WEC_CALN
112
112
113
114
116
120
125
129
WEC_LADW
28
28
28
28
28
30
31
32
WEC_SDGE
22
22
22
22
22
23
24
25
WECC_AZ
89
91
93
99
104
110
115
120
WECC_CO
63
64
66
70
73
78
82
86
WECC_ID
23
23
23
24
25
26
27
28
WECC_IID
4
5
5
5
5
5
5
6
WECC_MT
13
13
13
14
14
15
16
16
WECC_NM
23
24
24
26
27
29
30
32
WECC_NNV
13
13
13
13
14
15
15
16
WECC_PNW
174
176
178
184
190
199
209
217
WECC_SCE
110
110
110
111
114
118
122
127
WECC_SNV
26
27
28
29
31
33
34
36
WECC_UT
28
28
29
29
30
32
33
35
WECC WY
17
17
18
18
19
20
21
22
3
-------
Table 4 National Non-Coincidental Net Internal Demand for the High Demand Scenario
Year
Peak Demand (GW)
Winter
Winter Shoulder
Summer
2021
657
607
775
2023
672
620
791
2025
688
634
809
2030
720
663
847
2035
753
693
888
2040
796
731
939
2045
841
772
994
2050
887
813
1048
3. Low Demand
EPA Platform v6 low demand scenario run has adopted demand data from AEO 2018 with CPP case.
This scenario run implies 4.2% lower demand by 2030 and 5.2% lower demand by 2050 incremental to
the initial run.
For the low demand scenario, Table 5 and Table 6 present the net energy for load on a national and
regional basis respectively. Table 7 illustrates the national sum of each region's seasonal peak demand
and Table 44 presents each region's seasonal peak demand. In the EPA Platform v6 full-fledged
documentation, Table 5 and Table 6 correspond to Table 3-2 and Table 3-3 respectively and Table 7 and
Table 44 correspond to Table 3-4 and Table 3-18 respectively.
Table 5 Electric Load Assumptions for the Low Demand Scenario
Year
Net Energy for Load (Billions of kWh)
2021
4,066
2023
4,084
2025
4,109
2030
4,178
2035
4,266
2040
4,404
2045
4,549
2050
4,711
Table 6 Regional Electric Load Assumptions for the Low Demand Scenario
IPM Region
Net Energy for Load (Billions of kWh)
2021
2023
2025
2030
2035
2040
2045
2050
ERC_FRNT
0
0
0
0
0
0
0
0
ERC_GWAY
0
0
0
0
0
0
0
0
ERC_PHDL
0
0
0
0
0
0
0
0
ERC_REST
351
356
361
374
388
406
423
440
ERC_WEST
28
28
29
30
31
32
34
35
FRCC
239
240
242
248
257
269
282
296
MIS AMSO
33
34
34
36
37
39
40
41
-------
IPM Region
Net Energy for Load (Billions of kWh)
2021
2023
2025
2030
2035
2040
2045
2050
MIS_AR
39
40
41
42
43
45
47
48
MIS_D_MS
23
23
24
25
25
27
27
28
MIS_IA
22
22
22
23
23
24
25
25
MIS IL
46
46
47
47
48
50
51
53
MISJNKY
93
93
94
95
97
99
102
105
MIS_LA
48
48
49
51
53
55
57
59
MIS_LMI
102
102
102
103
105
107
110
114
MIS_MAPP
8
8
9
9
9
9
10
10
MIS_MIDA
30
30
30
31
32
33
34
35
MIS_MNWI
89
90
91
93
95
99
102
105
MIS_MO
39
39
40
40
41
42
44
45
MIS_WOTA
35
35
36
37
38
40
42
43
MIS_WUMS
65
65
66
67
68
70
72
74
NENG_CT
30
29
29
28
28
28
28
28
NENG_ME
10
10
10
10
10
10
10
10
NENGREST
77
75
75
73
72
72
72
72
NY_Z_A
16
16
16
15
15
15
15
16
NY_Z_B
10
10
10
10
10
10
10
10
NY_Z_C&E
24
24
24
23
23
23
24
24
NY_Z_D
7
6
6
6
6
6
6
6
NY_Z_F
12
12
11
11
11
11
11
11
NY_Z_G-I
18
18
18
18
17
17
17
18
NY_Z_J
47
46
46
44
43
42
42
43
NY_Z_K
20
20
19
19
18
18
19
19
PJM_AP
45
45
46
46
47
48
50
51
PJM_ATSI
67
67
67
68
70
71
73
75
PJM_COMD
97
97
98
100
101
104
107
110
PJM_Dom
97
98
99
102
105
109
114
119
PJM_EMAC
138
137
136
135
136
138
141
145
PJM_PENE
17
17
17
17
17
17
17
18
PJM_SMAC
63
63
62
62
62
63
65
66
PJM_West
203
203
205
208
212
217
223
230
PJM_WMAC
55
55
54
54
54
55
56
58
S_C_KY
31
32
32
33
34
35
36
38
S_C_TVA
173
175
177
182
187
193
200
207
S_D_AECI
18
18
18
18
18
19
20
20
S_SOU
237
240
243
250
257
267
278
288
S_VACA
224
226
228
235
243
253
263
274
SPP_KIAM
0
0
0
0
0
0
0
0
SPP_N
71
71
72
74
75
78
81
84
SPP_NEBR
34
34
34
35
36
37
38
39
SPP SPS
29
29
30
31
32
33
35
36
5
-------
IPM Region
Net Energy for Load (Billions of kWh)
2021
2023
2025
2030
2035
2040
2045
2050
SPP_WAUE
23
23
23
24
24
25
26
27
SPP_WEST
128
130
132
137
142
148
154
160
WEC_BANC
14
14
14
14
13
14
14
14
WEC_CALN
110
110
108
107
106
108
110
114
WEC_LADW
27
27
27
26
26
26
27
28
WEC_SDGE
21
21
21
21
20
21
21
22
WECC_AZ
90
91
92
94
97
102
107
113
WECC_CO
66
67
68
70
72
75
79
83
WECCJD
22
22
22
23
23
24
24
25
WECC_IID
4
5
5
5
5
5
5
5
WECC_MT
13
13
13
13
13
14
14
15
WECC_NM
24
24
24
25
26
27
28
30
WECC_NNV
13
13
13
13
13
13
14
14
WECC_PNW
172
172
173
174
176
181
188
195
WECC_SCE
108
107
106
105
104
106
108
112
WECC_SNV
27
27
27
28
29
30
32
33
WECC_UT
28
28
28
28
28
29
30
31
WECC WY
17
17
17
18
18
19
19
20
Table 7 National Non-Coincidental Net Internal Demand for the Low Demand Scenario
Year
Peak Demand (GW)
Winter
Winter Shoulder
Summer
2021
651
602
767
2023
653
604
769
2025
659
608
775
2030
673
620
792
2035
694
638
818
2040
722
663
853
2045
754
690
892
2050
790
721
938
4. High Renewable Energy Technology Cost
EPA Platform v6 high renewable energy technology cost scenario run uses cost data from NREL ATB
high levelized cost for energy (LCOE) case as opposed to mid-level LCOE case in the initial run. This
translates into 42% higher LCOE for onshore wind and 77% higher LCOE for solar PV over the 2030 to
2050 period. While the high LCOE assumptions for new solar PV, new solar thermal, and new onshore
wind units are from NREL ATB 2017, the assumptions for new offshore wind units are from NREL ATB
2016.
Table 8 lists updates included in EPA Platform v6 high renewable energy technology cost scenario that
are supplemental to the EPA Platform v6.
6
-------
Table 8 Updates in the High Renewable Energy Technology Cost Scenario
Description
Table
Corresponding
Table in EPA
Platform v6
Short-Term Capital Cost Adders for New Power Plants in High RE Technology
Cost Scenario
Table 9
Table 4-14
Performance and Unit Cost Assumptions for Potential (New) Renewable
Capacity in High RE Technology Cost Scenario
Table 10
Table 4-16
Onshore Average Capacity Factor by Wind TRG1 and Vintage in High RE
Technology Cost Scenario
Table 11
Table 4-20
Onshore Reserve Margin Contribution by Wind TRG and Vintage in High RE
Technology Cost Scenario
Table 12
Table 4-21
Offshore Shallow Average Capacity Factor by Wind TRG and Vintage in High
RE Technology Cost Scenario
Table 13
Table 4-22
Offshore Shallow Reserve Margin Contribution by Wind TRG and Vintage in
High RE Technology Cost Scenario
Table 14
Table 4-23
Offshore Mid-Depth Average Capacity Factor by Wind TRG and Vintage in High
RE Technology Cost Scenario
Table 15
Table 4-24
Offshore Mid-Depth Reserve Margin Contribution by Wind TRG and Vintage in
High RE Technology Cost Scenario
Table 16
Table 4-25
Offshore Deep Average Capacity Factor by Wind TRG and Vintage in High RE
Technology Cost Scenario
Table 17
Table 4-26
Offshore Deep Reserve Margin Contribution by Wind TRG and Vintage in High
RE Technology Cost Scenario
Table 18
Table 4-27
Solar Photovoltaic Reserve Margin Contribution by Resource Class in High RE
Technology Cost Scenario
Table 19
Table 4-32
Wind Generation Profiles in High RE Technology Cost Scenario
Table 45
Table 4-37
Solar Photovoltaic Generation Profiles in High RE Technology Cost Scenario
Table 46
Table 4-41
Solar Photovoltaic Capacity Factor by Resource Class and Cost Class in High
RE Technology Cost Scenario
Table 47
Table 4-44
1 TRG - Techno-resource group
7
-------
Table 9 Short-Term Capital Cost Adders for New Power Plants in the High Renewable Energy Technology Cost Scenario
Plant Type
2021
2023
2025
2030
2035
Step 1
Step 2
Step 3
Step 1
Step 2
Step 3
Step 1
Step 2
Step 3
Step 1
Step 2
Step 3
Step 1
Step 2
Step 3
Biomass
Upper Bound (MW)
1,904
3,312
No Limit
1,270
2,208
No Limit
1,270
2,208
No Limit
3,174
5,520
No Limit
3,174
5,520
No Limit
Adder ($/kW)
-
1,714
5,443
-
1,685
5,352
-
1,646
5,230
-
1,543
4,903
-
1,466
4,658
Coal Steam - UPC
Upper Bound (MW)
18361
31,932
No Limit
12,241
21,288
No Limit
12,241
21,288
No Limit
30,602
53,220
No Limit
30,602
53,220
No Limit
Adder ($/kW)
-
1,640
5,209
-
1,610
5,115
-
1,572
4,992
-
1,468
4,664
-
1,390
4,415
Combined Cycle
Upper Bound (MW)
132,125
229,782
No Limit
88,083
153,188
No Limit
88,083
153,188
No Limit
220,208
382,970
No Limit
220,208
382,970
No Limit
Adder ($/kW)
-
490
1,555
-
481
1,528
-
469
1,491
-
433
1,376
-
406
1,290
Combustion Turbine
Upper Bound (MW)
66,275
115,260
No Limit
44,183
76,840
No Limit
44,183
76,840
No Limit
110,458
192,100
No Limit
110,458
192,100
No Limit
Adder ($/kW)
-
298
945
-
291
924
-
281
893
-
255
809
-
235
747
Fuel Cell
Upper Bound (MW)
1,725
3,000
No Limit
1,150
2,000
No Limit
1,150
2,000
No Limit
2,875
5,000
No Limit
2,875
5,000
No Limit
Adder ($/kW)
-
3,101
9,850
-
3,007
9,551
-
2,896
9,200
-
2,615
8,305
-
2,386
7,578
Geothermal
Upper Bound (MW)
883
1,536
No Limit
589
1,024
No Limit
589
1,024
No Limit
1,472
2,560
No Limit
1,472
2,560
No Limit
Adder ($/kW)
-
3,772
11,983
-
3,763
11,954
-
3,744
11,892
-
3,700
11,754
-
3,636
11,549
Landfill Gas
Upper Bound (MW)
625
1,088
No Limit
417
725
No Limit
417
725
No Limit
1,042
1,813
No Limit
1,042
1,813
No Limit
Adder ($/kW)
-
3,979
12,639
-
3,915
12,437
-
3,822
12,140
-
3,577
11,361
-
3,379
10,733
Nuclear
Upper Bound (MW)
32,327
56,220
No Limit
21,551
37,480
No Limit
21,551
37,480
No Limit
53,878
93,700
No Limit
53,878
93,700
No Limit
Adder ($/kW)
-
2,499
7,939
-
2,347
7,456
-
2,287
7,264
-
2,127
6,757
-
2,005
6,368
Solar Thermal
Upper Bound (MW)
2,830
4,921
No Limit
1,886
3,281
No Limit
1,886
3,281
No Limit
4,716
8,202
No Limit
4,716
8,202
No Limit
Adder ($/kW)
-
2,340
7,432
-
2,840
9,022
-
2,830
8,989
-
2,806
8,913
-
2,771
8,801
Solar PV
Upper Bound (MW)
25,858
46,265
No Limit
18,406
32,011
No Limit
18,406
32,011
No Limit
46,016
80,027
No Limit
46,016
80,027
No Limit
Adder ($/kW)
-
513
1,629
-
590
1,874
-
590
1,874
-
590
1,874
-
590
1,874
Onshore Wind
Upper Bound (MW)
33,941
67,466
No Limit
30,238
52,588
No Limit
30,238
52,588
No Limit
75,595
131,470
No Limit
75,595
131,470
No Limit
Adder ($/kW)
-
700
2,222
-
699
2,219
-
697
2,213
-
693
2,200
-
687
2,181
Offshore Wind
Upper Bound (MW)
1,725
3,000
No Limit
1,150
2,000
No Limit
1,150
2,000
No Limit
2,875
5,000
No Limit
2,875
5,000
No Limit
Adder ($/kW)
-
2,475
7,863
-
2,472
7,853
-
2,466
7,832
-
2,451
7,786
-
2,429
7,717
Hydro
Upper Bound (MW)
10,360
18,018
No Limit
6,907
12,012
No Limit
6,907
12,012
No Limit
17,267
30,030
No Limit
17,267
30,030
No Limit
Adder ($/kW)
-
1,043
3,313
-
1,043
3,313
-
1,043
3,313
-
1,043
3,313
-
1,043
3,313
8
-------
Table 10 Performance and Unit Cost Assumptions for Potential (New) Renewable Capacity in the
High Renewable Energy Technology Cost Scenario
Solar PV
Solar Thermal
Onshore Wind
Offshore Wind
Size (MW)
150
100
100
400
First Year Available
2021
2021
2021
2021
Lead Time (Years)
1
3
3
3
Availability
90%
90%
95%
95%
Generation Capability
Generation
Profile
Economic
Dispatch
Generation
Profile
Generation
Profile
Vintage #1 (2021)
Capital (2016$/kW)
Fixed O&M (2016$/kW/yr)
Variable O&M (2016$/MWh)
1,514
13.17
0.0
6,983
66.87
4.1
1,560
51.67
0.0
5,521
137.22
0.0
Vintage #2 (2023)
Capital (2016$/kW)
Fixed O&M (2016$/kW/yr)
Variable O&M (2016$/MWh)
1,514
13.17
0.0
6,983
66.87
4.1
1,560
51.67
0.0
5,521
137.22
0.0
Vintage #3 (2025)
Capital (2016$/kW)
Fixed O&M (2016$/kW/yr)
Variable O&M (2016$/MWh)
1,514
13.17
0.0
6,983
66.87
4.1
1,560
51.67
0.0
5,521
137.22
0.0
Vintage #4 (2030)
Capital (2016$/kW)
Fixed O&M (2016$/kW/yr)
Variable O&M (2016$/MWh)
1,514
13.17
0.0
6,983
66.87
4.1
1,560
51.67
0.0
5,521
137.22
0.0
Vintage #5 (2035)
Capital (2016$/kW)
Fixed O&M (2016$/kW/yr)
Variable O&M (2016$/MWh)
1,514
13.17
0.0
6,983
66.87
4.1
1,560
51.67
0.0
5,521
137.22
0.0
Vintage #6 (2040)
Capital (2016$/kW)
Fixed O&M (2016$/kW/yr)
Variable O&M (2016$/MWh)
1,514
13.17
0.0
6,983
66.87
4.1
1,560
51.67
0.0
5,521
137.22
0.0
Vintage #7 (2045)
Capital (2016$/kW)
Fixed O&M (2016$/kW/yr)
Variable O&M (2016$/MWh)
1,514
13.17
0.0
6,983
66.87
4.1
1,560
51.67
0.0
5,521
137.22
0.0
Vintage #8 (2050)
Capital (2016$/kW)
Fixed O&M (2016$/kW/yr)
Variable O&M (2016$/MWh)
1,514
13.17
0.0
6,983
66.87
4.1
1,560
51.67
0.0
5,521
137.22
0.0
9
-------
Table 11 Onshore Average Capacity Factor by Wind TRG and Vintage in the High Renewable
Energy Technology Cost Scenario
TRG
Capacity Factor
Vintage #1 (2021-2054)
Vintage #2 (2030-2054)
Vintage #3 (2040-2054)
1
47%
47%
47%
2
46%
46%
46%
3
45%
45%
45%
4
44%
44%
44%
5
41%
41%
41%
6
36%
36%
36%
7
31%
31%
31%
8
25%
25%
25%
9
18%
18%
18%
10
11%
11%
11%
Table 12 Onshore Reserve Margin Contribution by Wind TRG and Vintage in the High Renewable
Energy Technology Cost Scenario
TRG
Vintage #1 (2021-2054)
Vintage #2 (2030-2054)
Vintage #3 (2040-2054)
1
0% - 69%
0% - 69%
0% - 69%
2
0% - 89%
0% - 89%
0% - 89%
3
0% - 89%
0% - 89%
0% - 89%
4
0% - 85%
0% - 85%
0% - 85%
5
0% - 78%
0% - 78%
0% - 78%
6
0% - 58%
0% - 58%
0% - 58%
7
0% - 45%
0% - 45%
0% - 45%
8
0% - 27%
0% - 27%
0% - 27%
Table 13 Offshore Shallow Average Capacity Factor by Wind TRG and Vintage in the High
Renewable Energy Technology Cost Scenario
TRG
Capacity Factor
Vintage #1 (2021-2054)
Vintage #2 (2030-2054)
Vintage #3 (2040-2054)
1
47%
47%
47%
2
43%
43%
43%
3
40%
40%
40%
Table 14 Offshore Shallow Reserve Margin Contribution by Wind TRG and Vintage in the High
Renewable Energy Technology Cost Scenario
TRG
Vintage #1 (2021-2054)
Vintage #2 (2030-2054)
Vintage #3 (2040-2054)
1
1 % - 82%
1 % - 82%
1 % - 82%
2
0% - 82%
0% - 82%
0% - 82%
3
0% - 84%
0% - 84%
0% - 84%
10
-------
Table 15 Offshore Mid-Depth Average Capacity Factor by Wind TRG and Vintage in the High
Renewable Energy Technology Cost Scenario
TRG
Capacity Factor
Vintage #1 (2021-2054)
Vintage #2 (2030-2054)
Vintage #3 (2040-2054)
5
47%
47%
47%
6
44%
44%
44%
Table 16 Offshore Mid-Depth Reserve Margin Contribution by Wind TRG and Vintage in the High
Renewable Energy Technology Cost Scenario
TRG
Vintage #1 (2021-2054)
Vintage #2 (2030-2054)
Vintage #3 (2040-2054)
5
0% - 78%
0% - 78%
0% - 78%
6
0% - 76%
0% - 76%
0% - 76%
Table 17 Offshore Deep Average Capacity Factor by Wind TRG and Vintage in the High Renewable
Energy Technology Cost Scenario
TRG
Capacity Factor
Vintage #1 (2021-2054)
Vintage #2 (2030-2054)
Vintage #3 (2040-2054)
8
49%
49%
49%
Table 18 Offshore Deep Reserve Margin Contribution by Wind TRG and Vintage in the High
Renewable Energy Technology Cost Scenario
TRG
Vintage #1 (2021-2054)
Vintage #2 (2030-2054)
Vintage #3 (2040-2054)
8
0% - 68%
0% - 68%
0% - 68%
Table 19 Solar Photovoltaic Reserve Margin Contribution by Resource Class in the High
Renewable Energy Technology Cost Scenario
Resource Class
CO
CO
CO
CM
Reserve Margin Contribution
0% -11% 0% - 29% 0% - 49% 0% - 46% 0% - 47% 0% - 51% 0% - 45%
5. Low Renewable Energy Technology Cost
EPA Platform v6 low renewable energy technology cost scenario run has uses data from NREL ATB low
LCOE case as opposed to mid-level LCOE case in the initial run. This translates into 26% lower LCOE
for onshore wind and 30% lower LCOE for solar PV over the 2030 to 2050 period. While the low LCOE
assumptions for new solar PV, new solar thermal, and new onshore wind units are from NREL ATB 2017,
the assumptions for new offshore wind units are from NREL ATB 2016.
Table 20 lists updates included in EPA Platform v6 low renewable energy technology cost scenario that
are supplemental to the EPA Platform v6.
11
-------
Table 20 Updates in the Low Renewable Energy Technology Cost Scenario
Description
Table
Corresponding
Table in EPA
Platform v6
Short-Term Capital Cost Adders for New Power Plants in Low RE Technology Cost
Scenario
Table 21
Table 4-14
Performance and Unit Cost Assumptions for Potential (New) Renewable Capacity in Low
RE Technology Cost Scenario
Table 22
Table 4-16
Onshore Average Capacity Factor by Wind TRG and Vintage in Low RE Technology Cost
Scenario
Table 23
Table 4-20
Onshore Reserve Margin Contribution by Wind TRG and Vintage in Low RE Technology
Cost Scenario
Table 24
Table 4-21
Offshore Shallow Average Capacity Factor by Wind TRG and Vintage in Low RE
Technology Cost Scenario
Table 25
Table 4-22
Offshore Shallow Reserve Margin Contribution by Wind TRG and Vintage in Low RE
Technology Cost Scenario
Table 26
Table 4-23
Offshore Mid-Depth Average Capacity Factor by Wind TRG and Vintage in Low RE
Technology Cost Scenario
Table 27
Table 4-24
Offshore Mid-Depth Reserve Margin Contribution by Wind TRG and Vintage in Low RE
Technology Cost Scenario
Table 28
Table 4-25
Offshore Deep Average Capacity Factor by Wind TRG and Vintage in Low RE
Technology Cost Scenario
Table 29
Table 4-26
Offshore Deep Reserve Margin Contribution by Wind TRG and Vintage in Low RE
Technology Cost Scenario
Table 30
Table 4-27
Solar Photovoltaic Reserve Margin Contribution by Resource Class in Low RE
Technology Cost Scenario
Table 31
Table 4-32
Wind Generation Profiles in Low RE Technology Cost Scenario
Table 48
Table 4-37
Solar Photovoltaic Generation Profiles in Low RE Technology Cost Scenario
Table 49
Table 4-41
Solar Photovoltaic Capacity Factor by Resource Class and Cost Class in Low RE
Technology Cost Scenario
Table 50
Table 4-44
12
-------
Table 21 Short-Term Capital Cost Adders for New Power Plants in the Low Renewable Energy Technology Cost Scenario
Plant Type
2021
2023
2025
2030
2035
Step 1
Step 2
Step 3
Step 1
Step 2
Step 3
Step 1
Step 2
Step 3
Step 1
Step 2
Step 3
Step 1
Step 2
Step 3
Biomass
Upper Bound (MW)
1,904
3,312
No limit
1,270
2,208
No limit
1,270
2,208
No limit
3,174
5,520
No limit
3,174
5,520
No limit
Adder ($/kW)
-
1,714
5,443
-
1,685
5,352
-
1,646
5,230
-
1,543
4,903
-
1,466
4,658
Coal Steam - UPC
Upper Bound (MW)
18361
31,932
No limit
12,241
21,288
No limit
12,241
21,288
No limit
30,602
53,220
No limit
30,602
53,220
No limit
Adder ($/kW)
-
1,640
5,209
-
1,610
5,115
-
1,572
4,992
-
1,468
4,664
-
1,390
4,415
Combined Cycle
Upper Bound (MW)
132,125
229,782
No limit
88,083
153,188
No limit
88,083
153,188
No limit
220,208
382,970
No limit
220,208
382,970
No limit
Adder ($/kW)
-
490
1,555
-
481
1,528
-
469
1,491
-
433
1,376
-
406
1,290
Combustion Turbine
Upper Bound (MW)
66,275
115,260
No limit
44,183
76,840
No limit
44,183
76,840
No limit
110,458
192,100
No limit
110,458
192,100
No limit
Adder ($/kW)
-
298
945
-
291
924
-
281
893
-
255
809
-
235
747
Fuel Cell
Upper Bound (MW)
1,725
3,000
No limit
1,150
2,000
No limit
1,150
2,000
No limit
2,875
5,000
No limit
2,875
5,000
No limit
Adder ($/kW)
-
3,101
9,850
-
3,007
9,551
-
2,896
9,200
-
2,615
8,305
-
2,386
7,578
Geothermal
Upper Bound (MW)
883
1,536
No limit
589
1,024
No limit
589
1,024
No limit
1,472
2,560
No limit
1,472
2,560
No limit
Adder ($/kW)
-
3,772
11,983
-
3,763
11,954
-
3,744
11,892
-
3,700
11,754
-
3,636
11,549
Landfill Gas
Upper Bound (MW)
625
1,088
No limit
417
725
No limit
417
725
No limit
1,042
1,813
No limit
1,042
1,813
No limit
Adder ($/kW)
-
3,979
12,639
-
3,915
12,437
-
3,822
12,140
-
3,577
11,361
-
3,379
10,733
Nuclear
Upper Bound (MW)
32,327
56,220
No limit
21,551
37,480
No limit
21,551
37,480
No limit
53,878
93,700
No limit
53,878
93,700
No limit
Adder ($/kW)
-
2,499
7,939
-
2,347
7,456
-
2,287
7,264
-
2,127
6,757
-
2,005
6,368
Solar Thermal
Upper Bound (MW)
2,830
4,921
No limit
1,886
3,281
No limit
1,886
3,281
No limit
4,716
8,202
No limit
4,716
8,202
No limit
Adder ($/kW)
-
2,171
6,897
-
2,368
7,523
-
2,094
6,653
-
1,427
4,532
-
1,253
3,982
Solar PV
Upper Bound (MW)
25,858
46,265
No limit
18,406
32,011
No limit
18,406
32,011
No limit
46,016
80,027
No limit
46,016
80,027
No limit
Adder ($/kW)
-
312
991
-
327
1,039
-
308
979
-
261
830
-
235
747
Onshore Wind
Upper Bound (MW)
33,941
67,466
No limit
30,238
52,588
No limit
30,238
52,588
No limit
75,595
131,470
No limit
75,595
131,470
No limit
Adder ($/kW)
-
672
2,135
-
630
2,001
-
584
1,856
-
462
1,469
-
444
1,410
Offshore Wind
Upper Bound (MW)
1,725
3,000
No limit
1,150
2,000
No limit
1,150
2,000
No limit
2,875
5,000
No limit
2,875
5,000
No limit
Adder ($/kW)
-
1,978
6,283
-
1,781
5,657
-
1,710
5,430
-
1,537
4,883
-
1,446
4,593
Hydro
Upper Bound (MW)
10,360
18,018
No limit
6,907
12,012
No limit
6,907
12,012
No limit
17,267
30,030
No limit
17,267
30,030
No limit
Adder ($/kW)
-
1,043
3,313
-
1,043
3,313
-
1,043
3,313
-
1,043
3,313
-
1,043
3,313
13
-------
Table 22 Performance and Unit Cost Assumptions for Potential (New) Renewable and Non-
Conventional Technology Capacity in the Low Renewable Energy Technology Cost Scenario
Solar PV
Solar Thermal
Onshore Wind
Offshore Wind
Size (MW)
150
100
100
400
First Year Available
2021
2021
2021
2021
Lead Time (Years)
1
3
3
3
Availability
90%
90%
95%
95%
Generation Capability
Generation
Profile
Economic
Dispatch
Generation Profile
Generation
Profile
Vintage #1 (2021)
Capital (2016$/kW)
Fixed O&M (2016$/kW/yr)
Variable O&M (2016$/MWh)
887
10.13
0.0
6,123
60.28
3.5
1,245
47.24
0.0
4,096
113.40
0.0
Vintage #2 (2023)
Capital (2016$/kW)
Fixed O&M (2016$/kW/yr)
Variable O&M (2016$/MWh)
839
10.13
0.0
5,552
55.89
3.5
1,186
45.77
0.0
3,736
109.80
0.0
Vintage #3 (2025)
Capital (2016$/kW)
Fixed O&M (2016$/kW/yr)
Variable O&M (2016$/MWh)
791
10.13
0.0
4,982
51.50
3.5
1,120
44.29
0.0
3,628
107.80
0.0
Vintage #4 (2030)
Capital (2016$/kW)
Fixed O&M (2016$/kW/yr)
Variable O&M (2016$/MWh)
671
10.13
0.0
3,551
40.53
3.5
928
40.60
0.0
3,357
102.90
0.0
Vintage #5 (2035)
Capital (2016$/kW)
Fixed O&M (2016$/kW/yr)
Variable O&M (2016$/MWh)
604
10.13
0.0
3,159
40.53
3.5
935
38.75
0.0
3,222
100.90
0.0
Vintage #6 (2040)
Capital (2016$/kW)
Fixed O&M (2016$/kW/yr)
Variable O&M (2016$/MWh)
536
10.13
0.0
3,008
40.53
3.5
928
36.91
0.0
3,087
98.80
0.0
Vintage #7 (2045)
Capital (2016$/kW)
Fixed O&M (2016$/kW/yr)
Variable O&M (2016$/MWh)
470
10.13
0.0
2,885
40.53
3.5
908
35.06
0.0
2,965
97.40
0.0
Vintage #8 (2050)
Capital (2016$/kW)
Fixed O&M (2016$/kW/yr)
Variable O&M (2016$/MWh)
403
10.13
0.0
2,783
40.53
3.5
877
33.22
0.0
2,843
96.10
0.0
14
-------
Table 23 Onshore Average Capacity Factor by Wind TRG and Vintage in the Low Renewable
Energy Technology Cost Scenario
TRG
Capacity Factor
Vintage #1 (2021-2054)
Vintage #2 (2030-2054)
Vintage #3 (2040-2054)
1
53%
56%
58%
2
51%
55%
57%
3
51%
55%
57%
4
50%
54%
56%
5
48%
53%
56%
6
45%
51%
54%
7
40%
46%
49%
8
33%
38%
41%
9
26%
32%
35%
10
17%
21%
23%
Table 24 Onshore Reserve Margin Contribution by Wind TRG and Vintage in the Low Renewable
Energy Technology Cost Scenario
TRG
Vintage #1 (2021-2054)
Vintage #2 (2030-2054)
Vintage #3 (2040-2054)
1
0% - 91%
0% - 96%
0%-100%
2
0% - 91%
0% - 97%
0%-100%
3
0% - 89%
0% - 96%
0%-100%
4
0% - 89%
0% - 96%
0%-100%
5
0% - 87%
0% - 95%
0%-100%
6
0% - 70%
0% - 79%
0% - 84%
7
0% - 67%
0% - 77%
0% - 82%
8
0% - 80%
0% - 93%
0%-100%
Table 25 Offshore Shallow Average Capacity Factor by Wind TRG and Vintage in the Low
Renewable Energy Technology Cost Scenario
TRG
Capacity Factor
Vintage #1 (2021-2054)
Vintage #2 (2030-2054)
Vintage #3 (2040-2054)
1
53%
54%
54%
2
48%
49%
50%
3
44%
45%
46%
Table 26 Offshore Shallow Reserve Margin Contribution by Wind TRG and Vintage in the
Low Renewable Energy Technology Cost Scenario
TRG
Vintage #1 (2021-2054)
Vintage #2 (2030-2054)
Vintage #3 (2040-2054)
1
0% - 57%
0% - 58%
0% - 58%
2
0% - 83%
0% - 85%
0% - 86%
3
0% - 93%
0% - 94%
0% - 96%
15
-------
Table 27 Offshore Mid-Depth Average Capacity Factor by Wind TRG and Vintage in the Low
Renewable Energy Technology Cost Scenario
TRG
Capacity Factor
Vintage #1 (2021-2054)
Vintage #2 (2030-2054)
Vintage #3 (2040-2054)
5
52%
53%
54%
6
49%
50%
50%
Table 28 Offshore Mid-Depth Reserve Margin Contribution by Wind TRG and Vintage in
the Low Renewable Energy Technology Cost Scenario
TRG
Vintage #1 (2021-2054)
Vintage #2 (2030-2054)
Vintage #3 (2040-2054)
5
0% - 57%
0% - 58%
0% - 58%
6
0% - 62%
0% - 63%
0% - 63%
Table 29 Offshore Deep Average Capacity Factor by Wind TRG and Vintage in the Low Renewable
Energy Technology Cost Scenario
TRG
Capacity Factor
Vintage #1 (2021-2054)
Vintage #2 (2030-2054)
Vintage #3 (2040-2054)
8
55%
56%
56%
Table 30 Offshore Deep Reserve Margin Contribution by Wind TRG and Vintage in the Low
Renewable Energy Technology Cost Scenario
TRG
Vintage #1 (2021-2054)
Vintage #2 (2030-2054)
Vintage #3 (2040-2054)
8
0% - 41%
0% - 42%
0% - 42%
Table 31 Solar Photovoltaic Reserve Margin Contribution by Resource Class in the Low
Renewable Energy Technology Cost Scenario
Resource Class
CO
CO
CO
CM
Reserve Margin Contribution
0% -13% 0% - 62% 0% - 73% 0% - 64% 0% - 87% 0% - 97% 0% - 92%
6. Higher Natural Gas Cost
EPA Platform v6 high gas price scenario run uses natural gas supply curves that reflect lower Estimated
Ultimate Recovery (EUR) growth and higher LNG exports. Natural gas prices in this scenario run are
between $3.27 and $5.61. This translates into 16% higher prices in 2030 and 31% higher prices by 2050
incremental to the initial run. The following summarizes the key drivers and associated assumptions that
are different from those in the initial run.
Exploration and Production Uncertainty
Natural gas market development remains imperative for continued supply growth. Petrochemical activity
both domestically and internationally as well as continued increases in power generation fueled by natural
gas will underpin the market growth. Absent such growth, development of incremental oil and gas from
lower cost plays will do nothing more than cannibalize development from less cost effective plays.
Awareness of which plays have a cost advantage and will hold up the best in such an environment is
important for capital preservation. Identifying the most robust assets is critical.
16
-------
Corresponding Well EUR Growth Adjustment
ICF employs a "learning curve" concept to estimate the contributions of changing technologies to the
hydrocarbon resource. The "learning curve" describes the aggregate influence of learning and new
technologies as having a certain percent effect on a key productivity measure (for example cost per unit
of output or feet drilled per rig per day) for each doubling of cumulative output volume or other measure of
industry/technology maturity. The learning curve shows that advances are rapid (measured as percent
improvement per period of time) in the early stages when industries or technologies are immature and
that those advances decline through time as the industry or technology matures.
In GMM, the learning curve concept is applied to the well EUR, the cumulative volume of hydrocarbon
that can be produced throughout the life of a well. In the EPA Platform v6 initial run, ICF estimates an
average of 20% EUR learning curve growth for every doubling of well completions. In other words, the
average EUR of a well is increased by 20% for every doubling of well completions. In the high gas price
scenario, the EUR improvement is assumed to be cut in half.
LNG Exports Uncertainty
In the global LNG market, there is significant uncertainty surrounding the total size of the market and the
market share that the US will be able to capture. Factors that could increase the size of the global LNG
market include:
• Less natural gas supply development in other areas around the world
• Less competition from international pipeline development
• Environmental regulations in global markets that favor natural gas over coal and renewables
• Faster rates of economic growth, particularly in Asia
• Faster rates of natural gas demand growth in the power generation sector, also particularly in
Asia
• Higher oil prices
• Shift towards a larger spot market for LNG
• Other LNG exporting nations have slower supply development
Corresponding LNG Exports Adjustment
The EPA Platform v6 high gas price scenario run assumes that there will be higher demand for LNG
exports from the U.S. and that there will be more export capacity built to accommodate that increased
demand. In addition to the export facilities assumed to be built in the EPA Platform v6 initial run, the high
gas price scenario run assumes that Corpus Christi Stage 3, Cameron LNG trains 4 and 5, Jordan Cove
LNG, Magnolia LNG, Lake Charles LNG, Driftwood LNG, and Rio Grande LNG will be built. Table 32
summarizes the LNG export assumptions in the EPA Platform v6 Initial run and the high gas price
scenario run. The high gas price scenarios run includes 8.2 Bcf/d of additional LNG exports from the US
in 2035 and 10.8 Bcf/d of additional LNG exports from the US in 2050.
Table 32 LNG Export Assumptions (Bcf/d)
EPA Platform v6 Initial Run
EPA Platform v6 High Gas Price
Scenario Run
2021
6.83
6.83
2023
8.42
8.42
2025
10.03
10.67
2030
12.72
15.78
2035
12.72
20.92
2040
12.98
23.74
2045
12.98
23.74
2050
12.98
23.74
17
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The natural gas supply curves and the natural gas seasonal price adders as implemented in the high gas
price scenario are shown in Table 51 and Table 52 respectively.
7. Tax Law Update
EPA Platform v6 tax law update scenario run incorporates updates to reflect The Tax Cuts and Jobs Act
of 20172. The capital charge rates in the tax law update run now vary by run year and are slightly lower
(less than 10% reduction) than those in the initial run. The discount rate increases from 3.9% to 4.25%.
The discussion below summarizes the revised assumptions.
7.1 Introduction
The new law lowered the federal corporate tax rate from 35% to 21% and made other changes in
corporate income tax provisions. As a result, the financing costs of power sector investments are now
expected to be lower than was the case prior to the passage of the bill, and lower than was in the EPA
Platform v6 initial run. The financing costs will decrease, all else held equal, because financing costs
include payment of income and other taxes necessary to recover and earn a return on capital; that level is
now lower. The two key financing parameters used in EPA's case—capital charge rate and discount
rate—reflect the now lower corporate income taxes:
• Capital Charge Rate - The capital charge rate equals the ratio of the annuitized Earnings Before
Interest, Taxes, Depreciation, and Amortization (EBITDA) to investment (I) (i.e., EBITDA/I).
EBITDA equals the funds available to pay taxes and provide the required return on and of capital.
• Weighted Average After Tax Cost of Capital (WACC) - The IPM model minimizes the
discounted costs and uses the WACC as its discount rate for calculating the present value of all
costs. The WACC is the average of two components: equity and debt. First, the WACC weights
required return on equity on an aftertax basis by the equity share of capitalization. Second, the
WACC weights the debt interest expense rate (usually the interest rate) on an aftertax basis; the
interest rate is multiplied by (1-income tax rate). The tax rate decreases the cost of interest
because of the tax deductibility of interest. The WACC is now higher because the corporate tax
rate is lower. As a result, future costs are discounted more relative to near term costs.
As discussed further below, interest expense is no longer fully deductible for a portion of the industry in a
given year, but is deductible in later years. In addition, the degree of deductibility in a given year varies
year by year with the variation affected by more than one factor. While the impact of various tax code
changes can cause the effectiveness of the tax shield as calculated to vary across time, a single WACC
is used in IPM.
7.2 Summary of Results
7.2.1 Capital Charge Rates
The real capital charge rate for a new combined cycle coming on-line in 2021 is the representative
investment for the real capital charge rate for exposition purposes. The first run year for EPA Platform v6
using IPM is 2021, and the combined cycle is the most frequently added new thermal power plant. (Table
37, Table 38, and Table 39 below present year-by-year and technology-by-technology results.) The real
capital charge rate for a new combined cycle on-line in 2021 decreases by approximately 0.49
percentage points due to the new tax law from the previous level of 9.15% (see Table 33). The decrease
is modestly higher for the independent power producer (IPP) sector compared to the utility sector as
2 The Tax Cuts and Jobs Act of 2017, Pub.L. 115-97.
18
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shown in Table 33. For example, the real capital charge rate of a new IPP combined cycle decreases
0.79 percentage points from 11.68% to 10.89%, which is a 6.8% decrease in the capital charge rate.
Table 33 Real Capital Charge Rate for New Combined Cycle
First Model Run Year (%
,3
Sector
Previous (A)
New (B)
Absolute Change
(B)-(A)
% Change
((B-A) /(A))*100
IPP
11.68
10.89
-0.79
-6.8
Utility
8.06
7.67
-0.39
-4.8
Blended (70% utility, 30% IPP)
9.15
8.66
-0.49
-5.4
7.2.2 WACC
Table 34 shows the absolute increase in the nominal WACC of 0.35 percentage point and the percentage
increase of approximately 6.0%. The WACC increases because the tax shield on debt decreases from
39.2% to 26.1%.4 In other words, as the tax rate decreases, the net, after-tax cost of debt increases and
incremental investments require a higher return. The increase in returns means future costs, including
return of and on capital, are discounted more relative to near term costs; having dollars sooner is more
valuable as the opportunity cost of deferring earnings increases. This is because discounting is the
inverse of compounding growth. The increase is larger for IPPs because of their higher debt interest rate
and debt share of capital.
The real WACC given an inflation assumption of 1,83%5 increases from 3.9% to 4.25%.
Table 34 After Tax Weighted Average Cost of Capital (WACC) - Nominal (%)
Sector
Previous (A)
New (B)
Absolute Change
(B)-(A)
% Change
((B-A) /(A))*100
IPP
7.88
8.40
+0.52
+6.6
Utility
4.92
5.20
+0.28
+5.7
Blended (70% utility 30% IPP)
5.81
6.16
+0.35
+6.0
3 The EPA Platform v6 initial run reflected a real capital charge rate for a new Combined Cycle of 9.13%. This was
the effect of weighting each parameter (e.g., debt share, ROE) by 70%:30% for utility and IPP builds, respectively,
and then calculating the actual capital charge rate. We are now calculating each capital charge rate (utility and IPP)
separately and then weight the results by the 70%:30% utility/IPP build ratio. This is because of the much greater
divergence between utilities and IPPs in terms of tax law. Specifically, utilities are the only companies exempted from
key provisions on depreciation, net operating losses, and tax deductibility. This minor refinement of the methodology
has a small impact on the calculation. Under the proposed new methodology, the real CCR for CC is higher by much
less than a percent - i.e., increases from 9.13% to 9.15%.
4 As noted, these tax rates include the impact of the average state income tax rate of 6.45%, which is deductible for
federal tax purposes.
5 Financial literature frequently uses nominal terms, and hence, we frequently present nominal results to facilitate
explanation. The expected inflation rate used to convert future nominal to constant real dollars is 1.83%. The future
inflation rate of 1.83% is based on an assessment of implied inflation from an analysis of yields on 10 year U.S.
Treasury securities and U.S. Treasury Inflation Protected Securities (TIPS) over a period of 5 years (2012-2016) with
a downward adjustment to account for the historically higher Consumer Price Index (CPI) inflation rate than Gross
Domestic Product (GDP) deflator (GDP deflator is the preferred measure of general economy wide inflation) inflation
rate over the 2007 to 2016 period.
19
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7.3 Federal Income Tax Law Changes
The four most significant changes in the federal corporate income tax code are:
• Rate - Corporate tax rate is lowered 14 percentage points from 35%6 to 21%; the 21% rate is in
place starting in 2018 and remains in place indefinitely; the lower tax rate decreases financing
costs in all periods and all sectors, all else held equal. When state income taxes are included,
the average rate decreases 13.1 percentage points, from 39.2% to 26.1%.
• Depreciation - The new tax law expands near term bonus depreciation (also referred to as
expensing) for the IPP sector until 2027.
• Interest Expense - The new law lowers tax deductibility of interest expense for the IPP sector,
which continues indefinitely.
• Net Operating Losses - The new law limits the use of Net Operating Losses (NOL).
Other important features of the new tax law include:
• Annual Variation of Provisions - The legislation specifies permanent changes (tax rate and
NOL usage limit), and temporary changes that vary year-by-year through to 2027 (depreciation
and tax deductibility of interest) (See Table 35). This creates different capital charge rates for
each year through 2027. We calculate these parameters for IPM run years 2021, 2023, 2025,
and 2030 and thereafter. This set covers a wide range of financing conditions even though we do
not estimate every year.
Table 35 Summary Tax Changes
Parameter
Previous
20217
2023
2025
2030 and Later
Marginal Tax Rate -
Federal
35
21
21
21
21
Maximum NOL (Net
Operating Loss)
Carry Forward
Usage
No limit. All losses
in excess of
income are carried
forward and
usable
immediately.
Carry Forward
cannot exceed
80% of Taxable
Income
Carry Forward
cannot exceed
80% of Taxable
Income
Carry Forward
cannot exceed
80% of Taxable
Income
Carry Forward
cannot exceed 80%
of Taxable Income
Tax Deductibility of
Interest Expense
100%8
IPP 30% of
EBITDA;
Utilities MACRS
30% of EBIT;
Utilities MACRS
30% of EBIT;
Utilities MACRS
30% of EBIT;
Utilities MACRS
Bonus
Depreciation9
Q10
IPP 100%;
Utilities 0%
IPP 80%11;
Utilities 0%
IPP 40%12;
Utilities 0%
0
• Utilities Versus IPPs - The legislation treats utilities and non-utilities (Independent Power
Producers - IPPs) differently. The new tax code exempts utilities from changes in tax
deductibility of interest and accelerated depreciation. The financing assumptions used in IPM
modeling are a blend (weighted average) of the utility and IPP average. The weighting is 70%
6 The average state income tax rate is 6.45 percent. State income tax is deductible, and hence, the combined rate is
39.2% (39.2=35+(1-0.35)*6.45). Underthe new 21% rate, the new average combined rate is 26.1%.
7 IPM run years in the near term are 2021, 2023, 2025, and 2030.
8 No limit except losses in excess of income can be carried forward. The losses were limited to first few years.
9 Referred to as expensing. If depreciation exceeds income in first year, it can be carried forward to succeeding
years up to 80% of EBITDA.
10 Bonus depreciation was available but only in the period before IPM runs, and only for new equipment.
11 For thermal power plants coming on line in 2023, the 100% would apply only to costs incurred through end of 2022.
We are hence assuming practically all capital costs are incurred prior to 2023.
12 Remaining basis depreciated at MACRS schedule.
20
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utility and 30% IPP, and hence, the greatest weight is on the least affected sector. This partly
mitigates the impacts of the changes. However, potentially offsetting is the IPP sector's heavy
reliance on high cost debt financing, and the high capital intensity of power production.
• Partly Offsetting Effects - The changes in the tax code affecting IPPs include offsetting effects
that yield net lower costs. The constraints on interest expense deductions and NOL usage raise
financing costs, while bonus depreciation and the lower tax rate lower costs (all else held equal).
If the only change for IPPs was the federal corporate tax rate being set to 21% - i.e., other tax law
changes affecting IPPs only did not occur-the impact on the real capital charge rate would have
been similar. That is, the real IPP capital charge rate would have been 10.99% versus 10.89%
for the impact of all changes.
• Near Term Versus Long Term - Overtime, IPP costs increase because of the higher interest
costs due to restricted deductibility and lower IPP decreased bonus depreciation (see Table 36).
Table 36 Impacts Over Time - Capital Charge Rate New Combined Cycle (%)
Year
Utility
IPP
Blended
2021
7.67
10.89
8.64
2023
7.67
10.89
8.64
2025
7.67
10.97
8.66
2030 and Beyond
7.67
11.33
8.77
• Renewables - The legislation has minor direct potential impacts on the renewable sector's tax
credits via the Base Erosion Anti-Abuse Tax (BEAT). The maximum effect of BEAT could
decrease the value of PTC and ITC by up to 20%13; estimates of the expected impact are not yet
available. In addition, the total decrease in corporate income taxes may decrease tax credit
appetite accordingly. Nevertheless, as we lack requisite data at this time we do not apply any
additional changes to renewable financing beyond the above-mentioned changes, which affect all
capacity types.
7.4 Capital Charge Rates: Utility, IPP, Blended Impacts - All Technologies
We summarize capital charge rates by plant types in Table 37, Table 38 and Table 39; these vary
because of different financing risks and costs, lifetimes, and depreciation schedules.
13 https://www.conqress.qov/115/bills/hr1/BILLS-115hr1enr.xml. "Part VII - Base Erosion and Anti-Abuse Tax, Sec
59A, Tax in Base Erosion Payments of Taxpayers with Substantial Gross Receipts, (b), (1), (B), (ii), (II) the portion of
the applicable section 38 credits not in excess of 80 percent of the lesser of the amount..."
See also https://www.mwe.com/en/thouaht-leadership/publications/2017/12/renewable-enerav-tax-bill-update-no-
chanqe-ptc-itc. A company's regular tax liability reflects certain credits that make it more likely that such a company
is subject to the BEAT. However, the Bill provides that only 20 percent of the PTC and ITC be taken into account.
Thus, 20 percent of the PTC and ITC might be denied depending on a company's BEAT status and relevant
computations in a given year.
21
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Table 37 Real Capital Charge Rate - Blended (%)
New Investment Technology Capital
Hybrid (70/30 Utility/Merchant)
Previous
Capital
Charge
Rate14
Revised to
Incorporate
New Tax
Code - 2021
Revised to
Incorporate
New Tax
Code -
2023
Revised to
Incorporate
New Tax
Code - 2025
Revised to
Incorporate
New Tax
Code - 2030
and Beyond
Environmental Retrofits - Utility Owned
11.29%
10.77%
10.77%
10.77%
10.77%
Environmental Retrofits - Merchant
Owned
15.62%
14.05%
14.05%
14.12%
14.54%
Advanced Combined Cycle
9.13%
8.64%
8.64%
8.66%
8.77%
Advanced Combustion Turbine
9.42%
9.02%
9.02%
9.02%
9.10%
Ultra Supercritical Pulverized Coal
without Carbon Capture15
11.80%
10.96%
10.96%
11.01%
11.18%
Ultra Supercritical Pulverized Coal with
Carbon Capture
8.76%
8.31%
8.31%
8.32%
8.43%
Nuclear
8.56%
8.31%
8.31%
8.33%
8.43%
Nuclear without Production Tax Credit
8.56%
8.31%
8.31%
8.33%
8.43%
Nuclear with Production Tax Credit16
7.20%
7.10%
7.09%
7.10%
7.19%
Biomass
8.47%
8.14%
8.12%
8.12%
8.12%
Wind, Landfill Gas, Solar and
Geothermal
10.00%
9.79%
9.78%
9.77%
9.77%
Hydro
8.53%
8.09%
8.09%
8.11%
8.21%
Table 38 Real Capital Charge Rate - IPP (%)
New Investment Technology
Capital (IPP)
Previous
Capital
Charge
Rate -
100% IPP
Revised to
Incorporate
New Tax
Code - 2021
Revised to
Incorporate
New Tax
Code - 2023
Revised to
Incorporate
New Tax
Code - 2025
Revised to
Incorporate
New Tax
Code - 2030
and Beyond
Environmental Retrofits - Merchant
Owned
15.62%
14.05%
14.05%
14.12%
14.54%
Advanced Combined Cycle
11.68%
10.89%
10.89%
10.97%
11.33%
Advanced Combustion Turbine
12.84%
11.83%
11.81%
11.81%
12.07%
Ultra Supercritical Pulverized Coal
without Carbon Capture
15.90%
14.05%
14.06%
14.23%
14.78%
Ultra Supercritical Pulverized Coal
with Carbon Capture
12.48%
11.22%
11.22%
11.27%
11.62%
Nuclear without Production Tax
Credit
11.99%
11.22%
11.22%
11.29%
11.62%
Nuclear with Production Tax Credit
9.99%
9.71%
9.69%
9.71%
10.00%
Biomass
10.83%
10.60%
10.56%
10.53%
10.53%
14 These capital charge rates are from the EPA Platform v6 initial run and were estimated by weighting each
parameter (e.g., debt share, ROE) by 70%:30% for utility and IPP builds, respectively, and then calculating the actual
capital charge rate.
15 EPA has adopted the procedure followed in ElA's Annual Energy Outlook 2013; the capital charge rates shown for
Supercritical Pulverized Coal and Integrated Gasification Combined Cycle (IGCC) without Carbon Capture include a
3% adder to the cost of debt and equity. See Levelized Cost of New Generation Resources in the Annual Energy
Outlook 2013 (p.2), http://www.eia.gov/forecasts/aeo/er/pdf/electricitv qeneration.pdf
16 The Energy Policy Act of 2005 (Sections 1301, 1306, and 1307) provides a production tax credit (PTC) of 18
mills/kWh for 8 years up to 6,000 MW of new nuclear capacity. The financial impact of the credit is reflected in the
capital charge rate shown in for "Nuclear with Production Tax Credit (PTC)." NEEDS v6 integrates 2,200 MW of new
nuclear capacity at Vogtle nuclear power plant. Therefore, in EPA Platform v6 only 3,800 MW of incremental new
nuclear capacity will be provided with this tax credit.
22
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New Investment Technology
Capital (IPP)
Previous
Capital
Charge
Rate -
100% IPP
Revised to
Incorporate
New Tax
Code - 2021
Revised to
Incorporate
New Tax
Code - 2023
Revised to
Incorporate
New Tax
Code - 2025
Revised to
Incorporate
New Tax
Code - 2030
and Beyond
Wind, Landfill Gas, Solar and
Geothermal
11.92%
11.77%
11.73%
11.70%
11.70%
Hydro
11.32%
10.61%
10.61%
10.67%
11.01%
Table 39 Real Capital Charge Rate - Utility (%)
New Investment Technology
Capital Utility
Previous
Capital
Charge
Rate -
100%
Utility
Revised to
Incorporate
New Tax
Code - 2021
Revised to
Incorporate
New Tax
Code - 2023
Revised to
Incorporate
New Tax
Code - 2025
Revised to
Incorporate
New Tax
Code - 2030
and Beyond
Environmental Retrofits - Utility
Owned
11.29%
10.77%
10.77%
10.77%
10.77%
Advanced Combined Cycle
8.06%
7.67%
7.67%
7.67%
7.67%
Advanced Combustion Turbine
8.17%
7.82%
7.82%
7.82%
7.82%
Ultra Supercritical Pulverized Coal
without Carbon Capture
10.20%
9.63%
9.63%
9.63%
9.63%
Ultra Supercritical Pulverized Coal
with Carbon Capture
7.41%
7.06%
7.06%
7.06%
7.06%
Nuclear without Production Tax
Credit
7.36%
7.06%
7.06%
7.06%
7.06%
Nuclear with Production Tax Credit
6.17%
5.98%
5.98%
5.98%
5.98%
Biomass
7.36%
7.08%
7.08%
7.08%
7.08%
Wind, Landfill Gas, Solar and
Geothermal
9.18%
8.94%
8.94%
8.94%
8.94%
Hydro
7.42%
7.01%
7.01%
7.01%
7.01%
7.5 Background, Caveats, Implications and Perspectives
7.5.1 Combined Cycle Parameters
As a reminder, the EPA Platform v6 financing assumptions and results include the following parameters
for a new combined cycle (see Table 40).
Table 40 New Combined Cycle - Selected Unchanged Parameters (%)
Parameter
Value
Debt Equity Utility
50:50
Debt Equity IPP - Combined Cycle
55:45
ROE - Utility
7.2
ROE - IPP
12.16
Debt Interest Rate - Utility
4.33
Debt Interest Rate - IPP
7.2
Share of Utility and IPP in Blended Average
70:30
State income tax rate
6.45
General Inflation Rate
1.83
Risk Free Rate
3.45
23
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7.5.2 Capital Charge Rate Change - Illustrative Example of Price Impacts
In a competitive market, price equals marginal cost. If a new combined cycle is the marginal new power
plant, the lower capital charge rate would lower marginal cost and power price. The determination of
average wholesale power price involves many factors including reserve costs, fuel costs, the variation in
demand and supply fundamentals, etc. However, the average cost of a combined cycle correlates with
long term average price if it is the marginal unit on a prolonged basis. Therefore, to understand
approximately the impact on power price of the change in the capital charge rate, the following calculation
is presented in Table 41.
If a new combined cycle costs approximately $1,000/kWto build, the new tax law lowers the annual
levelized real costs by $4.90/kW (0.49 % percentage point change shown above in Table 37, times a
capital cost of $1000/KW). If the unit dispatches at an annual capacity factor of 55%17, this reduction in
capital charge rate decreases the levelized costs of the unit by $1.01/MWh18. If fuel costs are assumed to
be $24.5/MWh19 and non-fuel operating and maintenance costs are assumed to be $5/MWh, the
reduction in levelized real cost are about 2.1%.20 The impact is less than the 5.3% decrease in the capital
cost (i.e., a decrease of 2.1% a compared to a decrease of 5.3%) because two-thirds of the costs are not
capital related. The summary results are shown in Table 41.
Table 41 Illustrative Costs of New Combined Cycle ($/MWh)
Cost
Previous
Revised
Absolute Change
% Change
Fuel
24.5
24.5
0
0
Non Fuel Operating and Maintenance
5.0
5.0
0
0
Capital
19.0
18.0
-1
-5.3
Total
48.5
47.5
-1
-2.1
7.5.3 Capital Charge Rate Changes - Share of Total Income Tax Contribution to Capital Charge
Rates
If under the previous corporate income tax law, the corporate tax rate was zero (i.e., no income taxes
state or federal), and there were no other changes, the capital charge rate would have fallen from 9.15%
to 8.06% (absolute decrease of 1.09%), or approximately 12% decrease on a percentage basis. Thus,
the 9.15% to 8.67% actual decrease of 0.48% percentage point is approximately 44% of the maximum
decrease (0.48/1.09).
Table 42 Illustrative Capital Charge Rate21 - New Combined Cycle %)
Federal Tax Rate (%)
Capital Charge Rate - New Combined Cycle (%)
35
9.15
21
8.67
0
8.06
17 The average capacity factor for natural gas fired combined cycle units in the U.S. in the last three years was
approximately 55%. See https://www.eia.gov/electricitv/monthlv/epm table arapher.php?t=epmt 6 07 a
18 This compares to the original annualized capital costs of $18.99/MWh based on a capital charge rate of 9.15%
(0.0915*$1000/kW*1000kW/MW*(1/8760 hrs)*(1/0.55 CF) = $18.99/MWh). The reduction in levelized costs is
0.0049*$1000/kW*1 OOOkW/MW *(1/8760 hrs) x (1/0.55CF)=$1,01/MWh.
19 Assumes for illustrative purposes, heat rate of 7,000 Btu/KWh and a delivered natural gas fuel cost of $3.5/MMBtu.
20 Total Levelized costs of $48.5/MWh = $19/MWh annualized capital +$24.5$/MWh fuel +$5.0/MWh O&M.
$1,01/MWh is 2.1 % of this cost.
21 Blended combining utility and IPP capital charge rates.
24
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7.5.4 Taxes and After Tax Return on Equity Levels
This analysis assumes that the after tax required return on equity (ROE) does not increase. However, it
is possible that as the tax rate is lowered, the after tax cost of equity capital increases, all else held equal.
For illustration, see Figure 7-1 where the lowering of the tax increases the aftertax ROE (Y-axis is return
in percentage, and the x-axis is quantity of equity). In this illustration, the vertical distance between the
supply curves (for a given quantity of equity supplied to the market) going from no tax to a higher tax level
is the extra return required to cover corporate income taxes. As the tax rate decreases, the equilibrium
point (intersection of demand and supply curves) implies greater investment22 and a higher aftertax ROE.
This analysis would apply also to any tax reduction, and vice versa, all else held equal.
It is beyond the scope of the present analysis to try to estimate the effects of the change in tax rates on
required returns. The supply and demand for equity is economy wide and modeling it would require an
analysis of the entire economy.
Figure 7-1 Supply and Demand of Equity under Varying Tax Rates - Illustrative
25
20
'5 15
O"
c
o
c
I—
3
4->
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List of tables that are directly uploaded to the web:
Table 43 Regional Net Internal Demand for the High Demand Scenario
Table 44 Regional Net Internal Demand for the Low Demand Scenario
Table 45 Wind Generation Profiles in the High Renewable Energy Technology Cost Scenario
Table 46 Solar Photovoltaic Generation Profiles in the High Renewable Energy Technology Cost
Scenario
Table 47 Solar Photovoltaic Capacity Factor by Resource Class and Cost Class in the High Renewable
Energy Technology Cost Scenario
Table 48 Wind Generation Profiles in the Low Renewable Energy Technology Cost Scenario
Table 49 Solar Photovoltaic Generation Profiles in the Low Renewable Energy Technology Cost Scenario
Table 50 Solar Photovoltaic Capacity Factor by Resource Class and Cost Class in the Low Renewable
Energy Technology Cost Scenario
Table 51 Natural Gas Supply Curves for the Higher Natural Gas Cost Scenario
Table 52 Natural Gas Seasonal Price Adders for the Higher Natural Gas Cost Scenario
26
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